The Accelerated Depreciation scheme allows developers to depreciate the solar assets 80-100% in the first year itself after capitalization of the assets resulting in major tax benefits to the AD based developer. The AD is used in financial statements which typically reflects diverse non RE business interests and areas to reduce/defer payment of taxes from these non-RE interests/areas. This has enabled AD dependent bidding organizations in winning projects despite lower equity commitment to the projects and at the cost of revenue to exchequer. To illustrate for clarity, if the debt: equity ratio is assumed @ 70:30, the upfront equity commitment reduces to ~5% when the AD benefits are factored in. Also AD leads to reduced tax liability by ~30-50%. It is clear that this benefit can be availed i.e. tax avoidance through reduction/deferment by investors who have large tax liability from other businesses. The impact also includes:

Significant loss of tax revenue to the exchequer amounting to Rs. ~23,000 Crores (for additional capacity addition of 17,500 MW as per the earlier capacity addition programme; this would be substantially higher for higher solar capacities under consideration).

Economic distortion leading to non-generating stranded assets.

Stress on financial sector as equity is recovered in 2 years and risk is borne by lenders(mostly public sector banks).

There is consensus that change from AD to GBI would prevent loss to exchequer and make the sector sustainable and can improve India’s focus on generation and weighted average CUF in wind from 21.2% to ~27%.

We request your kind consideration to the following suggestions:

The solar policy should encourage resource efficient generation where a capacity addition decision is taken based on proper assessment of all resources (including scarce resources like land and funds) for long term sustainable energy access and security. So instead of AD, GBI should be considered as an enabling incentive for both solar and wind.

Taking the international experience into consideration, it is suggested that AD may be withdrawn in favour of an overall cut in the corporate tax rate. It has been documented that economy wide tax break enables overall macroeconomic benefits.

The loss to the exchequer on account of AD should be routed to the NBFCs like IREDA, REC, and IIFCL amongst others. This will ensure more fund flows to be disbursed to the private developers at low rates of interest for new RE projects in the country.

Relaxation of MAT to enable new markets

Exemption of MAT over 10 years can be looked at as a key solution to the existing conflicts in the business growth of IPPs. This will enable more equity available to the developers to invest further in future projects creating a level playing field for AD and non-AD players.

RGO to be exclusive of RPO – so that it adds depth to the market

The Government has introduced RGO in addition to RPO in order to increase the depth of the RE market. While the objective is laudable – it will pose certain operational issues for IPPs and might actually hurt their interests and these will happen because as of now there is lack of clarity on the operationalization of the RGO scheme. Most important, PSU thermal generators will be getting a cost plus tariff with assured returns on costs incurred OR the CERC FIT whereas IPPs would be required to compete, often at the cost of reasonable returns. The above policy initiative begs clarity in the following areas:

What is the break-up of capacity target of 100 GW for the solar sector? Is this entire capacity envisaged under RPO?

Does the RGO regime allow thermal generators to buy solar power to fulfill RGO obligations or does it mandate that thermal generators should install the solar capacity themselves?

Is capacity under RGO exclusive of and in addition to capacity which would set up to comply to RPO?

Considering the fact that the solar power generated by thermal generators is ultimately going to be consumed by distribution licensees, and the cost is going to be passed on to the them, will not RGO tantamount to enhancing the obligation of Renewables purchase on the distribution licensees over and above that of RPO? Have the states consented to a package comprising of both RPO and RGO, particularly since this is going to impact them commercially?

If there is an overlap between RGO and RPO capacities, then there is a very strong likelihood that states will go ahead with thermal generators like NTPC who will offer them bundled power which would be cheaper than standalone solar power. Being a Central PSU, states will have a certain level of comfort with NTPC. With the RGO capacities being sold to state discoms, the procurement by states under RPO will come under a cloud. How will the RGO and RPO capacities be segregated and how will RPO be enforced? Also, if thermal generators utilize their thermal generation for bundling with their own solar power generation, then there would be little left to bundle with the solar power generation of IPPs, further creating a barrier for acceptance of IPP solar power by the state discoms.

What will be the tariff for the solar component of RGO? Is it true that this is going to be based on cost plus methodology for tariff determination with the CERC rate of return? Does it not lead to a non-level playing field in a context, when a FIT regime based on cost determination with a reasonable rate of return has been rejected in favour of competitive bidding for procurement of power from solar IPPs under the RPO regime?

Level playing field between PSU thermal generators and IPPs in the solar sector

To ensure a level playing field between various players in the market, no preferential treatment to PSUs by SECY/ MNRE should prevail. They should also compete with private sector players and should be allocated capacities not on nominations but through competitive bidding route only at tariffs determined through competitive bidding.

Procurement of power through competitive bidding under NSM Phase II Batch II Tranche I

NVVN has issued draft guidelines for selection of 3000 MW grid connected solar PV power projects under Phase II Batch II Tranche I State specific schemes. These guidelines envisage major changes in the prevalent bidding/ evaluation formats being used by NVVN, SECI and various states while inviting bids from various bidders for procurement of solar power through competitive bidding. Our submission is that the more we tinker with the form and formats of bidding, the more uncertainty we introduce into bidding. Bidders and investors like continuity of policies and procedures and you will appreciate that two-stage reverse bidding which was followed by NVVN during Phase I has had a high success rate and has been singularly responsible for the low default rate by bidders and, most important, for drastically lowering solar tariff. We would also like to emphasize on the fact that the regulatory regime in terms of a region wise FIT needs to be in place before a state wise bidding is initiated. Our key observations along with suggestions on the guidelines are as follows. We urge you to consider our views favorably.

The selection of bidders is being planned through e-bidding. There have been many instances of failed bid submissions in states where e-bidding was done. In an instance recently of Karnataka 50 MW solar tender in June 2014, almost 50% of bidders failed to submit their bids on time because of server congestion and crashing. In a NVVN bid, the probability of server congestion and crashing are higher because of the traditionally higher participation of bidders. In Karnataka, where e-bidding has been done in the past, developers who have failed to put in bids have routinely gone to the courts and have delayed the process - in some cases they have been allowed to submit their bids in hard copy formats thus vitiating the sanctity of the bidding process altogether. Therefore, E-bidding should not be done. The earlier process of bidding – two-stage bidding in hard copy formats should be continued with for the sake of continuity and avoidance of surprises. This has also won appreciation of investors.

The guidelines include capacities which have to be put up in solar parks. Three situations have been envisaged – (i) entire tendered capacity in solar park; (ii) part tendered capacity in solar park and part outside the park; (iii) entire tendered capacity outside the park. Now, if one were to draw a comparison with the conventional power sector, this is tantamount to asking investors to bid to supply capacity through either as a Case I or Case II bid for the same capacity available to bid. This is not likely to create a level playing field for all the bidders as the costs associated with development of a project within a solar park or for that matter the data sets may be very different to development of a project outside the park. We suggest that the MNRE consider bidding out projects individually either through (i) or (iii) and not merge the two as part of a single bid.

The guidelines envisage that the Solar Park Implementation Agency (SPIA) shall provide the details of land and the timelines for availability, allotment, possession and connectivity for the projects before submission of bids. The SPIA will provide the Cost of Land, Annual Charges, and Connectivity Charges etc. which the developer would take into consideration in their bid. Under the circumstances, it becomes imperative that two stage bidding is followed wherein Stage I is for compliance of technical qualifications and SPIA gives all the details of the solar park to the technical qualified bidders. Stage II will be for financial bidding based on inputs from SPIA.

The guidelines envisage doing away with tariff differentials between AD and non-AD based developers. Till now, if bidders availed AD benefit, that benefit was passed on to the consumers as indeed it should be. And hence the differential tariffs as mandated by the Central regulator as well. It is suggested that differential tariffs is continued between AD and non-AD developers.

The guidelines also suffer from some stark uncertainties and vagueness. Amongst the prominent ones are:

Uncertainty pertaining to timelines of tenders – tenders will be timed depending upon consents from the states. Nothing specific has been indicated as yet.

Quantum of capacity to be sourced through DCR – this is essential to communicate a firm road map to domestic manufacturers

Bid evaluation methodology – has not been specified and has been left to NVVN for all the three situations envisaged under the bid.

PPA counter-party – will it be NVVN or any other authority?

Capacity to be put up under the three situations (i) in solar park; (ii) in and outside solar park; (iii) outside solar park

Project sizes under each of the above situations

Absence of FIT based on DCR modules and for solar projects located in various solar resource regions will adversely affect the real tariff discovery and may hamper the long term sustainability of solar projects. It is imperative that CERC be impressed upon for assessing these FITs before NVVN comes out with these bids.

These bids are being based on CERC FIT tariff. However, the CERC cost assumptions do not include cost assumptions like SPIA fees. Also, from experiences of developers in Gujarat and Rajasthan solar parks, these fees and charges are escalated year on year. So here we have a situation where the benchmark tariff assumptions are not in sync with the actual cost assumptions which have to be factored in by bidders during the bidding stage as well as incurred by the successful bidders in the course of implementation and operation of projects in the solar park. This needs to be set right.

We would like to reiterate on our commitment to the vision of the Hon’ble Prime Minister for the RE sector and assure our full support and dedication to achieve the same with a win-win situation for all the players in the industry.